Methods of Using Wellbore Servicing Compositions

ABSTRACT

A method of servicing a wellbore comprising preparing a composition comprising a non-aqueous carrier fluid, an oil-wetting surfactant, a water-imbibition enhancing surfactant, and a cementitious material; placing the composition within a detrimentally permeable zone; and contacting the composition with water. A method of servicing a wellbore comprising placing a composition comprising a non-aqueous carrier fluid, an oil-wetting surfactant, a water-imbibition enhancing surfactant, and a cementitious material into the wellbore wherein the wellbore comprises hydrocarbon-producing zones and water-producing zones and wherein the composition enters the water-producing zone and forms a solid mass that obstructs the flow of water in the water-producing zone. A method of servicing wellbore comprising placing a composition comprising a non-aqueous carrier fluid, an oil-wetting surfactant, a water-imbibition enhancing surfactant, and a cementitious material into a lost circulation zone within the wellbore; and contacting the composition in situ with a water source.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a regular utility application which claims priority to U.S. Provisional Patent Application Ser. No. 61/655,190, filed Jun. 4, 2012 and entitled “Design Considerations of Oil-Based, Squeeze Cement Slurries to Prevent Unwanted Fluid Production: Methods of Slurry Performance Evaluation and Potential Formulation Improvements;” which is incorporated by reference herein in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

1. Technical Field

This disclosure relates to compositions for servicing a wellbore. More specifically, this disclosure relates to methods of treating water producing zones and zones of detrimental permeability.

2. Background

A natural resource such as oil or gas residing in a subterranean formation can be recovered by drilling a well into the formation. The subterranean formation is usually isolated from other formations using a technique known as well cementing. In particular, a wellbore is typically drilled down to the subterranean formation while circulating a drilling fluid through the wellbore. After the drilling is terminated, a string of pipe, e.g., casing, is run in the wellbore. Primary cementing is then usually performed whereby a cement slurry is pumped down through the string of pipe and into the annulus between the string of pipe and the walls of the wellbore to allow the cement slurry to set into an impermeable cement column and thereby seal the annulus.

Subsequently, oil or gas residing in the subterranean formation may be recovered by driving fluid into the well using, for example, a pressure gradient that exists between the formation and the wellbore, the force of gravity, displacement of the fluid using a pump or the force of another fluid injected into the well or an adjacent well. The production of the fluid in the formation may be increased by hydraulically fracturing the formation. That is, a viscous fracturing fluid may pumped down the wellbore to the formation at a rate and a pressure sufficient to form fractures that extend into the formation, providing additional pathways through which the oil or gas can flow to the well. Unfortunately, water rather than oil or gas may eventually be produced by the formation through the fractures therein. To provide for the production of more oil or gas, a fracturing fluid may again be pumped into the formation to form additional fractures therein. However, the previously used fractures first must be plugged to prevent the loss of the fracturing fluid into the formation via those fractures.

In addition to the fracturing fluid, other fluids used in servicing a wellbore may also be lost to the subterranean formation while circulating the fluids in the wellbore or otherwise placing fluids in the wellbore. In particular, the fluids may enter and be “lost” to the subterranean formation via depleted zones, zones of relatively low pressure, lost circulation zones having naturally occurring fractures, weak zones having fracture gradients exceeded by the hydrostatic pressure of the fluid, and so forth. As a result, the service provided by such fluid is more difficult to achieve. For example, a drilling fluid may be lost to the formation, resulting in the circulation of the fluid in the wellbore being terminated and/or too low to allow for further drilling of the wellbore. Such conditions may be referred to as partial or complete loss of circulation or lost circulation.

In addition to the loss of fluids to the formation, wellbore servicing operations may be detrimentally impacted by the production of water from subterranean formations designed to produce hydrocarbons, especially in mature wells. A method commonly used to address either the undesired loss of fluids to a formation (i.e., lost circulation) or to inhibit the introduction of water to a hydrocarbon-bearing formation (i.e., conformance control) is to reduce the permeability of zones that either serve as conduits for the influx of water or zones that serve as conduits for the efflux of wellbore servicing fluids which are collectively included herein as detrimentally permeable zones (DPZ). An ongoing need exists for compositions and methods that treat DPZs.

BRIEF SUMMARY

Disclosed herein is a method of servicing a wellbore comprising preparing a composition comprising a non-aqueous carrier fluid, an oil-wetting surfactant, a water-imbibition enhancing surfactant, and a cementitious material; placing the composition within a detrimentally permeable zone; and contacting the composition with water.

Also disclosed herein is a method of servicing a wellbore comprising placing a composition comprising a non-aqueous carrier fluid, an oil-wetting surfactant, a water-imbibition enhancing surfactant, and a cementitious material into the wellbore wherein the wellbore comprises hydrocarbon-producing zones and water-producing zones and wherein the composition enters the water-producing zone and forms a solid mass that obstructs the flow of water in the water-producing zone.

Also disclosed herein is a method of servicing wellbore comprising placing a composition comprising a non-aqueous carrier fluid, an oil-wetting surfactant, a water-imbibition enhancing surfactant, and a cementitious material into a lost circulation zone within the wellbore; and contacting the composition in situ with a water source.

The foregoing has outlined rather broadly the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter that form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.

DETAILED DESCRIPTION

Disclosed herein are compositions and methods for the treatment of DPZs. Herein, DPZs collectively refer to zones or areas within a subterranean formation whose presence or permeability detrimentally impacts one or more wellbore servicing operations. For example the DPZ may comprise a lost circulation zone such as voids, vugular zones, and natural or induced fractures. Alternatively, a DPZ may comprise water-producing areas in an intended hydrocarbon-producing wellbore. In an embodiment, compositions suitable for use in the treatment of DPZs comprise a non-aqueous carrier fluid, optionally a dehydrating agent, an oil-wetting surfactant, a water-imbibition enhancing surfactant, a cementitious material, and optionally a filler. Herein, these compositions are termed treatment compositions for detrimentally permeable zones and designated TREATs. In an embodiment, a method of servicing a wellbore comprises preparing a TREAT, placing the TREAT downhole, and contacting the DPZ with the TREAT.

In an embodiment, the TREAT comprises a hydraulic cement that sets and hardens by reaction with water. Examples of hydraulic cements include but are not limited to Portland cements (e.g., classes A, B, C, G, and H Portland cements), pozzolana cements, gypsum cements, phosphate cements, high alumina content cements, silica cements, high alkalinity cements, shale cements, acid/base cements, cement kiln dust cements, magnesia cements, fly ash cement, zeolite cement systems, cement kiln dust cement systems, slag cements, micro-fine cement, and combinations thereof.

In an embodiment, the cement may be present in the TREAT in an amount of from about 15 weight percent (wt. %) to about 90 wt. %, alternatively from about 30 wt. % to about 70 wt. % or alternatively from about 50 wt. % to about 60 wt. % based on the total weight of the composition.

In an embodiment, the TREAT comprises a filler. Herein, fillers refer to any inorganic material that is introduced to the composition in order to lower the consumption of the hydraulic cement. In some embodiments, such fillers may improve one or more properties of the composition in which it is included. In some embodiments said improvements may be due to conversion of the filler into cementitious material by reaction with one or more hydration products of the cement in the presence of water in reactions known as pozzolanic reactions. Examples of fillers suitable for use in this disclosure include without limitation pumice, ASTM Class F fly ash, sand, silica, metakaolin, slag, or combinations thereof.

In an embodiment, the filler may be present in the TREAT in an amount of from about 10 percent by weight of cement (bwoc) to about 200% bwoc, alternatively from about 25% bwoc to about 150% bwoc, or alternatively from about 50% bwoc to about 100% bwoc.

In an embodiment, the filler and/or hydraulic cement may be sized so as provide materials having an average particle size of equal to or less than about 50 microns, alternatively less than about 25 microns or alternatively less than about 5 microns. The average particle size refers to a median value of d50 obtained by using standard particle size measurement equipment and represents the particle sizes of half of the particles in the solid composition. In an embodiment, the cement and filler may be ground together to obtain a cementitious blend of desired particle sizes. For example, cement clinker may be ground together with pumice, perlite, slag, flyash, metakaolin or a combination of such materials. A nonlimiting example of a material suitable for use in this disclosure is FINECEM cement which is a fine particle, high surface area cement blend commercially available from Halliburton Energy Services, Inc.

In an embodiment, the TREAT comprises a non-aqueous carrier fluid. The non-aqueous carrier fluid may be a single fluid or a combination of fluids. In an embodiment, the non-aqueous carrier fluid may be any non-aqueous fluid that is chemically compatible with the other components of the TREAT and suitable for providing a pumpable slurry. In an alternative embodiment, the non-aqueous carrier fluid is any non-aqueous fluid that is chemically compatible with the other components of the TREAT with a flash point of equal to or greater than about 140° F. and suitable for providing a pumpable slurry. In an embodiment, the non-aqueous carrier fluid is an oleaginous fluid. Examples of oleaginous fluids suitable for use in a TREAT include, but are not limited to, petroleum oils, natural oils, synthetically-derived oils, oxygenated fluids, or combinations thereof. More particularly, examples of oleaginous fluids suitable for use in the present disclosure include, but are not limited to, diesel oil, kerosene oil, mineral oil, synthetic oil such as polyolefins (e.g., alpha-olefins and/or internal olefins), polydiorganosiloxanes, esters, diesters of carbonic acid, alcohols, alcohol esters, ethers, paraffins, or combinations thereof. Other examples of suitable non-aqueous carrier fluids include but are not limited to aliphatic hydrocarbons such as, internal olefins, linear alpha olefins, poly alpha olefins, diesel, mineral oil, kerosene, silicone fluids or combinations thereof. Alternatively, the non-aqueous carrier fluid is an oxygenated solvent such as ethylene glycol, ethylene glycol monoalkyl ether, ethylene glycol dialkyl ether or combinations thereof wherein the alkyl groups are methyl, ethyl, propyl, butyl and the like. In an embodiment, the density of non-aqueous carrier fluids suitable for use in this disclosure may be in the range of from about 0.7 g/cc to about 1.5 g/cc. The non-aqueous carrier fluid may be present in an amount of equal to or greater than about 10 wt. % by total weight of the TREAT, alternatively equal to or greater than about 15 wt. %, or alternatively equal to or greater than about 20 wt. %.

In an embodiment, the non-aqueous carrier fluid excludes water. Alternatively, the non-aqueous carrier fluid comprises less than about 5%, 4%, 3%, 2% or 1% water by total weight of the non-aqueous carrier fluid.

In an embodiment, the TREAT comprises a dehydrating agent. The dehydrating agent may function to reduce the water content of the non-aqueous carrier fluid upon contacting same. In an embodiment, the dehydrating agent is any material chemically compatible with the other components of the TREAT and able to reduce the water content of the non-aqueous carrier fluid. Alternatively, the dehydrating agent is any non-cementitious material with an affinity for water that is capable of reducing the water content of the non-aqueous carrier fluid to less than about 5%, 4%, 3%, 2% or 1% by weight when used in amounts of equal to or less than about 25% by weight of the non-aqueous carrier fluid.

In an embodiment, the dehydrating agent may comprise high surface area or highly porous materials containing hydrophilic surfaces. Examples of such dehydrating agents include without limitation high surface area silica, alumina, zeolitic materials, molecular sieve materials or combinations thereof. In an embodiment, the dehydrating agent comprises a zeolitic material. Zeolites are a group of natural or synthetic hydrated aluminosilicate minerals that contain alkali and alkaline metals. They are characterized by a framework structure that encloses interconnected cavities occupied by ion-exchangeable large metal cations and water molecules permitting reversible dehydration. An example of a suitable zeolitic material includes without limitation SILIPORITE molecular sieve which is a synthetic zeolite commercially available from Ceca Arkema Group.

In an embodiment, the dehydrating agent is an inorganic material for example an inorganic salt or combination of inorganic salts. Such salts may be hydroscopic salts, for example anhydrous calcium chloride, or salts from which waters of crystallization has been removed, for example anhydrous sodium sulfate, anhydrous calcium sulfate, or calcium oxide. In some embodiments the inorganic material may be a clay, for example bentonite, or an anhydrous cementiceous material such as Portland cement.

In an embodiment, the TREAT comprises at least two functional surfactants. In an embodiment, a first surfactant functions as an oil-wetting surfactant (OWS) and facilitates suspension of the cementitious material in the non-aqueous carrier fluid. In such an embodiment, the OWS is soluble in the non-aqueous carrier fluid. The OWS may be any material chemically compatible with the other components of the TREAT and having a hydrophilic-lipophilic balance (HLB) ratio of less than or equal to 7. The HLB is a system used to categorize surfactants according to the balance between the hydrophilic and lipophilic portions of their molecules. The HLB value indicates the polarity of the molecules in an arbitrary range of 1 to 40 with the most commonly used surfactants having a value of between 1 to 20. The HLB value increases with increasing hydrophilicity of the surfactant. Consequently, an OWS or one designed to promote compatibilization of the particulate cementitious material surface with the non-aqueous carrier fluid by rendering the surface of the cementitious material hydrophobic by adsorption via the hydrophilic head portion of the surfactant would have a low HLB value. The OWS may be a nonionic, anionic, or cationic. In an embodiment, the TREAT comprises at least one OWS with an HLB of less than or equal to 7. Alternatively, the TREAT may comprise more than one OWS which when combined have a calculated average HLB ratio of less than or equal to 7. Examples of a suitable OWS include without limitation nonylphenolethoxylates with less than 5 moles of ethylene oxide, fatty acids and their salts, alkali and alkaline earth metal salts of dodecybenzene sulfonic acid, sorbitan trioleate, sorbitan monopalmitate, sorbitan monostearate, propylene glycol monolaurate, propylene glycol monostearate, sorbitan distearate and any combination of such surfactants. Other examples of commercially available OWS include without limitation MOC A surfactant, OMC 2 thinner, OMC 3 thinner and OMC 42 thinner which are all commercially available from Halliburton Energy Services, Inc. In an embodiment, the OWS is utilized as a solution of the surfactant in a non-aqueous solvent that contains less than about 10 wt. % water. Non-aqueous solvents suitable for use in this disclosure are materials similar to those as described for the non-aqueous carrier fluid. The amount of the active surfactant in the solution may be in range of from about 10 wt. % to about 80 wt. % by weight of the surfactant solution.

In an embodiment, a TREAT comprises an OWS present in amounts of from about 0.1 wt. % to about 10 wt. %, alternatively from about 0.3 wt. % to about 6 wt. %, alternatively from about 0.5 wt. % to about 4 wt. % by weight of the non-aqueous carrier fluid.

In an embodiment, a second surfactant functions as a water-imbibition enhancing surfactant (WIES) and may aid in the hydration of the cementitious material that has been treated with an OWS surfactant and may contain hydrophobicized surfaces. More particularly, the WIES may aid in enhancing the water uptake or imbibition by cement in a non-aqueous carrier fluid that has been treated with an oil wetting surfactant and then exposed to water. Without wishing to be limited by theory, the presence of the WIES may enhance imbibition of water by cement the surface of which has been rendered hydrophobic both by treatment with a OWS and being slurried in a non-aqueous carrier fluid. The WIES may facilitate hydration reactions to take place ultimately to an extent that is similar to a cement that has been directly exposed to water only. Further, the WIES may aid in hydration of cement in such slurries even when the agitation or mixing with water is less than ideal for efficient mixing and hydration, for example under quiescent conditions. Imbibition of water by non-aqueous cement slurries in the presence of WIES may be accompanied by displacement of the non-aqueous fluid by water penetration or by emulsification of the non-aqueous fluid in water to form an oil-in-water emulsion or both. The function of the WIES is to convert the TREAT to a water-external phase with the non-aqueous fluid as the dispersed phase as well as to render the cement particle surfaces hydratable when contacted with water in the formation.

The WIES may be any surfactant material chemically compatible with the other components of the TREAT and having a HLB of greater than or equal to 10. Such a WIES may be nonionic, anionic or cationic. In an embodiment, the TREAT comprises at least one WIES with an HLB of greater than or equal to 10. Alternatively, the TREAT may comprise more than one WIES which when combined have a calculated average HLB ratio of greater than or equal to 10. An example of a suitable WIES includes without limitation DUAL SPACER B surfactant, which is an ethoxylated nonylphenol surfactant commercially available from Halliburton Energy Services, Inc. Other examples of suitable WIES are cationic quaternary ammonium salts, for example ARQUAD DMCB and ARQUAD DMHTB which are benzyl coco dimethyl ammonium chloride and dimethyl (hydrogenated tallow) benzyl ammonium chloride commercially available from AkzoNobel Corporation. Other suitable quaternary ammonium compounds include propoxylated diethanolamine methyl ammonium chloride, commercially available as EMCOL CC brand products from Akzo Nobel Corporation. Examples of other suitable WIES include without limitation polyoxyethylene sorbitan based surfactants, commonly referred to as TWEEN surfactants, for example, TWEEN® 20, TWEEN® 40, TWEEN® 60, TWEEN® 80, TWEEN® 81 or any combination such surfactants. Such materials are available from many surfactant vendors or from chemical companies such as Aldrich Chemical Company.

In an embodiment, the WIES may be predissolved in a non-aqueous solvent prior to its addition to TREAT. Suitable solvents to dissolve the WIES include alcohols, alcohol ethers, such as ethanol, isopropanol, methanol, 2-ethylhexanol ethylene glycol monomethyl ether or combination of such solvents. The concentrations active surfactant in such a solution may range from about 25 wt. % to about 85 wt. %. In an embodiment, the TREAT contains the WIES in amounts of from about 0.1 wt. % to about 10 wt. %, alternatively from about 0.3 wt. % to about 6 wt. %, alternatively from about 0.5 wt. % to about 4 wt. % by weight of total composition. In an embodiment, the OWS and WIES are used without predissolution in solvents of the type disclosed herein. In an embodiment, both the OWS and the WIES may be dissolved in a solvent to obtain a single solution for use with TREAT.

In an embodiment, a TREAT may be prepared by the addition of the components in any order desired by the user. Alternatively, the TREAT may be prepared by the addition of the components in the order to be described. In an embodiment, a TREAT is prepared by the addition of a dehydrating agent to the non-aqueous carrier fluid. In an embodiment, the dehydrating agent may be contacted with the non-aqueous carrier fluid prior to the addition of any other components of the TREAT and allowed to reduce the water content in the non-aqueous carrier fluid. The dehydrating agent and non-aqueous carrier fluid may be contacted for a time period sufficient to substantially dehydrate the non-aqueous carrier fluid. Herein, dehydration of the non-aqueous carrier fluid refers to reducing the amount of aqueous material in the non-aqueous carrier fluid to less than about 5%, 4%, 3%, 2% or alternatively less than 1% by weight of the non-aqueous carrier fluid. As will be understood by one of ordinary skill in the art, the time necessary to substantially dehydrate the non-aqueous carrier fluid will depend on numerous factors such as the amount of non-aqueous carrier fluid, the water content thereof, and the amount and nature of the dehydrating agent. As such, the time necessary for dehydration of the non-aqueous carrier fluid may be designed by one skilled in the art to meet the needs of the user. After the dehydration period, the non-aqueous carrier fluid may be separated from the dehydrating agent prior to mixing with the cement composition. The non-aqueous carrier fluid after contact with the dehydrating agent is termed the dehydrated non-aqueous carrier fluid.

In some embodiments, the non-aqueous carrier fluid is anhydrous. In such embodiments, the TREAT may exclude a dehydrating agent and a method of forming a TREAT may exclude contacting the non-aqueous carrier fluid with the dehydrating agent as described previously herein.

In an embodiment, the dehydrated non-aqueous carrier fluid (or anhydrous non-aqueous carrier fluid) is then contacted with the cementitious material and surfactants in any user and/or process desired order. In an embodiment, the OWS and WIES are combined and used simultaneously in the formation of the TREAT wherein the OWS and WIES are employed as a single solution in which the ratio OWS to WIES may vary from 1:9 to 9:1. Alternatively, the TREAT is prepared by sequential addition of the OWS and WIES. For example, the TREAT may be prepared by addition of the OWS to the non-aqueous carrier fluid, followed by addition of the cementitious material and subsequently addition of the WIES. In another embodiment, the WIES surfactant is added first to the non-aqueous carrier fluid, followed by addition of the cementitious material and subsequent addition of the OWS. In an embodiment, the OWS is added to non-aqueous carrier fluid followed by WIES with subsequent addition of the cementitious material. In an embodiment, cementitious material is added to the non-aqueous carrier fluid followed by the OWS and subsequent addition of the WIES. In all cases, the TREAT composition contains at least two functional surfactants and a cementitious material prior to entering the subterranean formation, or contacting water in the wellbore.

In some embodiments, additives may be included in the TREAT for improving or changing the properties thereof. Examples of such additives include but are not limited to salts, accelerants, set retarders, defoamers, fluid loss agents, weighting materials, dispersants, vitrified shale, formation conditioning agents, viscosifying agents, or combinations thereof. Other mechanical property modifying additives, for example, carbon fibers, glass fibers, metal fibers, minerals fibers, and the like can be added to further modify the mechanical properties. These additives may be included singularly or in combination. Methods for introducing these additives and their effective amounts are known to one of ordinary skill in the art. In an embodiment, the TREAT optionally comprises a suspension aid. The suspension aid may function to reduce or prevent the settling of cement particles and allow such particles to remain suspended in the TREAT. In an embodiment, the suspension aid comprises any material chemically compatible with the other components of the TREAT and able to reduce or prevent the settling of the cement particles. Alternatively, the suspension aid comprises a partially or completely soluble polymer, organically surface modified inorganic solids, for example organophilic clay, organophilic glass or mineral fibers and the like.

The TREATs prepared as disclosed herein may be used as wellbore servicing fluids. As used herein, a “servicing fluid” refers to a fluid used to drill, complete, work over, fracture, repair, or in any way prepare a wellbore for the recovery of materials residing in a subterranean formation penetrated by the wellbore. Examples of wellbore servicing fluids include, but are not limited to, cement slurries, drilling fluids or muds, spacer fluids, fracturing fluids or completion fluids. The servicing fluid is for use in a wellbore that penetrates a subterranean formation. It is to be understood that “subterranean formation” encompasses both areas below exposed earth and areas below earth covered by water such as ocean or fresh water.

In an embodiment, the TREAT functions to obstruct DPZs of the type described herein. For example, the TREAT may be introduced to the wellbore to prevent the loss of aqueous or non-aqueous drilling fluids into loss-circulation zones such as voids, vugular zones, and natural or induced fractures while drilling. In an embodiment, the TREAT is placed into a wellbore as a single stream where it may enter loss circulation zones. In one embodiment, a TREAT entering the loss-circulation zone remains as a suspension comprising unhydrated cementitious material until the suspension encounters water present in the wellbore and/or formation and the cementitious material is hydrated. The resultant hydrated TREAT may have features ranging from that associated with a gelatinous mass to those associated with a paste. In an embodiment, the hydrated TREAT forms a solid mass sufficient to obstruct the detrimentally permeable zone in which it is located and reduce loss circulation. In an embodiment, the hydrated TREAT forms a solid mass in less than about 5 minutes, alternatively in less than about 3 minutes, and alternatively in less than about 1 minute when mixed with water and agitation under laboratory conditions.

In another embodiment, the TREAT is placed into a wellbore in a stream alone or in combination with another stream of materials. For example, a second stream of aqueous fluid (e.g., water) may be placed in the wellbore before, concurrently/simultaneously, or after/sequentially with the first stream comprising the TREAT. For example, a first stream comprising the TREAT may be pumped through a flowbore of a tubular disposed in the wellbore (e.g., a work string, coiled tubing string, jointed pipe string, etc.) and a second stream comprising an aqueous fluid (e.g., water) may be pumped down an annular space formed between the tubular and the wellbore wall (e.g., casing wall), whereby the TREAT and the aqueous fluid mix downhole to form the hydrated TREAT that obstructs the DPZs. The TREAT present in or proximate to the loss circulation zones may contact the water introduced to the formation via the second stream and form a mass sufficient to obstruct the detrimentally permeable zone in which the TREAT is located and reduce loss circulation. It is to be understood the TREAT as placed into the wellbore comprises unhydrated cementitious material and is a suspension of the unhydrated cementitious material in non-aqueous carrier fluid, and the cement is subsequently hydrated via contact with an aqueous fluid downhole (e.g., a naturally occurring or in situ aqueous fluid such water produced from the formation and/or water placed downhole prior, concurrent/simultaneously, and/or after placement of the TREAT). It is also to be understood that when the TREAT penetrates oil producing zones, the cement in the TREAT remains unhydrated and TREAT will flow out of the oil producing zone without forming a solid mass or without lowering the permeability to oil either as the original or diluted slurry.

In an embodiment, the TREAT when placed into a wellbore enters one or more DPZs containing water produced by the subterranean formation. In such embodiments, the TREAT may form a viscous mass sufficient to obstruct the water-producing zone in which it is located. Thus, it is contemplated that TREATs of the type disclosed herein when placed in a DPZ are contacted with water that is endogenous to the DPZ (e.g., connate water, formation water, interstitial water, etc.) and/or may be contacted with water that is exogenous to the DPZ such as water placed in the subterranean formation during a wellbore servicing operation.

In an embodiment, the TREAT may be preceded by a pre-stream (referred to as preflush) of a non-aqueous fluid that may be the same, similar or different from the non-aqueous carrier fluid used to prepare the TREAT. The preflush may function to displace any water or an aqueous fluid present in the wellbore so as to prevent premature contact of an aqueous fluid with TREAT.

In an embodiment, a TREAT of the type disclosed herein when contacted with water develops a compressive strength of from about 50 psi to about 2000 psi, alternatively from about 100 psi to about 1000 psi, or alternatively from about 250 psi to about 750 psi. Herein, the compressive strength is defined as the capacity of a material to withstand axially directed pushing forces. The maximum resistance of a material to an axial force is determined in accordance with API Recommended Practices 10B-2, First Edition, July 2005.

It is contemplated in some embodiments the TREAT when contacted with water rapidly forms a solid mass sufficient to obstruct the flow of fluids into or from the DPZ in which the TREAT is located. Further, the cementitious material of the TREAT may hydrate so rapidly as to form a mass that prevents at least a portion of the TREAT from contacting water. For example, the water may contact the TREAT and a mass form at the point of contact of the water and TREAT such that the mass serves as an interface between the water and an unreacted portion of the TREAT. The depth of the interface may vary and will depend on a variety of factors such as the shape and dimensions of the DPZ in which the TREAT and water are contacted. In an embodiment, equal to or greater than about 25% of the TREAT forms a solid mass after contact with water in a DPZ, alternatively equal to or greater than about 30%, 35%, 40%, 45%, 50%, 55%, 60%, 65%, 70%, 75%, 80%, 85%, 90% or 95% of the TREAT forms a solid mass when contacted with water in a DPZ without agitation under laboratory conditions.

In an embodiment, the TREAT may be employed in well completion operations such as secondary cementing operations. In secondary cementing, often referred to as squeeze cementing, the TREAT may be strategically positioned in the wellbore to repair an area of lost structural integrity in a set cement sheath. For example, the TREAT when utilized in secondary cementing may plug a void or crack in the conduit, plug a void or crack in the hardened sealant (e.g., cement sheath) residing in the annulus, plug previously placed perforations (e.g., zones or areas previously subjected to a perforating operation), plug a relatively small opening known as a microannulus between the hardened sealant and the conduit, and so forth.

It is to be understood TREATs of the type disclosed herein are not intended for primary cementing and do not form sufficient compressive strength to support structures or articles such as for example a casing. It is to be understood TREATs of the type disclosed have cementitious material suspended in a non-aqueous carrier fluid until such time as the composition contacts water within the wellbore. Consequently, TREATS within the wellbore that do not contact water may remain as a non-aqueous fluid suspension of cementitious material for an indefinite time period. TREATs of this disclosure may obstruct DPZs in a sufficiently short time period making it unnecessary for the operator to pull out of the hole to address the problem and thus reducing nonproductive rig time. In some embodiments, a method of servicing a wellbore comprises introducing a TREAT of the type disclosed herein to the wellbore and shutting in the wellbore for some period of time.

EXAMPLES

The invention having been generally described, the following examples are given as particular embodiments of the invention and to demonstrate the practice and advantages thereof. It is understood that the examples are given by way of illustration and are not intended to limit the specification of the claims in any manner.

Example 1

The compressive strength of a TREAT of the type disclosed herein was compared to the compressive strength of cement slurries containing microfine particles. Three cement slurries were prepared: Sample A (Control) contained MICROMATRIX cement and MOC A surfactant in diesel; Sample B contained the same components as Sample A with the exception that MOC A surfactant was replaced with OMC 2 which is an non-aqueous drilling fluid conditioner and Sample C contained OMC 2, LOSURF 20N which is a cationic non-emulsifying surfactant and MICROMATRIX cement in diesel. MICROMATRIX cement, MOC A surfactant, OMC 2 fluid conditioner and LOSURF 20N which is a cationic non-emulsifying surfactant based on quaternized ammonium salt are all commercially available from Halliburton Energy Services, Inc. The general procedure for the preparation of the slurries was as follows: to 25 ml diesel containing 0.5 ml ((2% by volume of diesel) of MOC-A surfactant as OWS in a blender, 50 grams MICROMATRIX cement was added with vigorous stirring for 30 seconds. The slurries displayed excellent pourability and consistency at surfactant levels of 0.3-2% by volume of diesel when other OWS were tested. In order to test the ability of the slurry to form viscous mass upon mixing with water, five milliliters of water was added and stirred with a spatula vigorously. The time for the whole slurry to form a viscous, stiff non-flowing mass was measured. For the control slurry it was about 1 minute. For measurement of compressive strengths, the slurry was mixed with water (20 grams, 40% by weight of cement) and hand-mixed with a spatula until a uniform paste was formed. The paste was packed into 2×2×2 inch brass molds and cured in a water bath at 180° F. for 72 hours. Compressive strengths of the paste measured for three samples are presented in Table 1. Sample A was prepared as described above with MOC-A, an OWS based on dodecylbenzene sulfonic acid salt dissolved in non-aqueous solvents. Sample B was prepared according to the general procedure using OMC 2, an OWS based on oligomeric fatty acid solution in non-aqueous solvents. Sample C is a mixture of OMC 2 as OWS and LOSURF 20N as WIES and was prepared by adding WIES to a control slurry prepared as described above. LOSURF 20N is a mixture of benzyl group containing quaternized ammonium salts dissolved in non-aqueous solvents.

TABLE 1 Sample Set Cement Density (ppg) Crush Compressive Strength (psi) A 12.8 270 B 12.5 280 C 12.7 640

The results demonstrate that the inherent compressive strengths of the inventive compositions (i.e., Sample C) are more than double that of conventional cementitious compositions.

Example 2

Various TREATs of the type disclosed herein were prepared and their ability to imbibe water under static conditions was evaluated. Specifically, samples containing OWS/WIES surfactant combination as indicated in Table 2 were prepared according to the procedure and amounts described in the general procedure in Example 1. The amount of WIES solution was 0.5 ml. The amount of solid WIES, for example LOSURF 2000S, was 0.3 grams. LOWSURF 396 is a non-ionic surfactant, LOWSURF 2000S is a solid anionic surfactant mixed with a solid hydrotrope, and LOSURF 19N is a quaternary ammonium salt based on benzyl dimethyl coco ammonium chloride that is dissolved in a non-aqueous solvent system comprising oxygenated solvent. All tested surfactants are available from Halliburton Energy Services, Inc. The slurries were placed in an Erlenmeyer flask and water was poured gently down the walls of the flask to simulate contact of the samples with water within a DPZ and to ensure the slurry was not significantly disturbed or to minimize agitational mixing. The flask once filled with water was sealed off with a rubber-stopper fitted with a water-filled pipette such that the pipette tip was under water level in the flask. The changes to the level of water in the pipette were measured over 3-5 days at room temperature. At the end of the experiment the water in the flask was poured out. The cement crust was chipped carefully with a chisel and the thickness of the set crust and the thickness of the unset cement slurry were measured. The crust and unset slurry thickness provided a measure of the water imbibition or penetration into the cement. The results are shown in Table 2. The results demonstrate that the best results are observed when cationic WIES surfactants are used in combination with oil-wetting surfactants (OWS). The results also demonstrate that non-aqueous slurries for introduction into DPZs such as in squeeze cementing applications (e.g., TREATs) can be designed with performance superior to conventional materials for these applications.

TABLE 2 Surfactant OMC-2 + OMC-2 + OMC-2 + OMC-2 + LOSURF LOSURF LOSURF LOSURF MOC-A OMC-2 396 20N 2000S 19N Set cement 0.2 1 2 13-15 0.2 3-4 thickness (mm) Unset cement 14-15 15-17 15-17 1-3 16-18 12-14 thickness (mm)

Example 3

A mixture was prepared by adding to 25 ml diesel, 0.5 ml MOC-A surfactant and 0.5 gram solid dimethyl (hydrogenated tallow) benzyl ammonium chloride available as ARQUAD DMHTB from AKZO Nobel Corporation. 50 grams MICROMATRIX cement was then added to the mixture with stirring. The resulting slurry was transferred to a beaker and beaker was filled with water in a gentle stream to ensure minimum mixing. The mixture was stored at room temperature for 3 days. The water was poured out and the set cement thickness was measured. The set cement crust was about 85% of the cement slurry volume with a small amount of unset cement slurry underneath the set cement crust. The results demonstrate that quaternized ammonium compounds containing a long chain alkyl group and a benzyl group can function as effective WIES compounds.

Example 4

The general procedure described in Example 1 was repeated by replacing MICROMATRIX cement with a microfine Portland cement and pumice 1:1 blend that has been ground together to obtain an average particle size (d50) of 5 microns. Upon addition of water (5-40% by weight of Portland cement) and stirring with a spatula, the mixture formed a non-flowing viscous paste within two minutes at room temperature. This result demonstrates that cementitious blends that have ground together to obtain a solid blend of desired particle sizes will form solidified mass capable of blocking fluid flow in a DPZ and can be utilized in the inventive methods and compositions disclosed herein.

While preferred embodiments of the invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the invention. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the invention disclosed herein are possible and are within the scope of the invention. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.

Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as an embodiment of the present invention. Thus, the claims are a further description and are an addition to the preferred embodiments of the present invention. The discussion of a reference herein is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural or other details supplementary to those set forth herein. 

What is claimed is:
 1. A method of servicing a wellbore comprising: (a) preparing a composition comprising a non-aqueous carrier fluid, an oil-wetting surfactant, a water-imbibition enhancing surfactant, and a cementitious material; (b) placing the composition within a detrimentally permeable zone; and (c) contacting the composition with water.
 2. The method of claim 1 wherein the cementitious material comprises a hydraulic cement.
 3. The method of claim 2 wherein the cementitious material comprises Portland cements, pozzolana cements, gypsum cements, phosphate cements, high alumina content cements, silica cements, high alkalinity cements, shale cements, acid/base cements, magnesia cements, fly ash cement, zeolite cement systems, cement kiln dust cement systems, slag cements, micro-fine cement, or combinations thereof.
 4. The method of claim 1 wherein the composition further comprises a filler.
 5. The method of claim 4 wherein the filler comprises pumice, ASTM Class F fly ash, sand, silica, metakaolin, slag, or combinations thereof.
 6. The method of claim 1 wherein the cementitious material has an average particle size of equal to or less than about 50 microns.
 7. The method of claim 4 wherein the cementitious material has an average particle size of equal to or less than about 50 microns.
 8. The method of claim 1 wherein the cementitious material is present in the composition in an amount of from about 15 wt. % to about 90 wt. % based on the total weight of the composition.
 9. The method of claim 1 wherein the non-aqueous carrier fluid comprises internal olefins, linear alpha olefins, poly alpha olefins, diesel, mineral oil, kerosene, silicone fluids, oxygenated solvents, or combinations thereof.
 10. The method of claim 1 wherein the non-aqueous carrier fluid comprises less than about 5% water by total weight of the fluid.
 11. The method of claim 1 wherein the composition further comprises a dehydrating agent.
 12. The method of claim 1 wherein the oil-wetting surfactant has a hydrophilic-lipophilic balance of equal to greater than about
 7. 13. The method of claim 1 wherein the water-imbibition enhancing surfactant has a hydrophilic-lipophilic balance of greater than or equal to about
 10. 14. The method of claim 13, wherein the water-imbibition enhancing surfactant is a quaternary ammonium compound comprising a benzyl group and an alkyl group selected from the group consisting of a coco alkyl group and a hydrogenated tallow alkyl group.
 15. The method of claim 1 wherein the water contacting the cementitious composition is endogenous to the detrimentally permeable zone.
 16. The method of claim 1 wherein the water contacting the cementitious composition is exogenous to the detrimentally permeable zone.
 17. The method of claim 1 wherein a portion of the cementitious material forms a solid mass when contacted with water.
 18. The method of claim 17 wherein the portion of cementitious material that forms a solid mass when contacted with water is equal to or greater than about 75% of the cementitious material by weight.
 19. The method of claim 1 wherein the detrimentally permeable zone comprises an area of lost circulation.
 20. The method of claim 1 wherein the detrimentally permeable zone comprises a water-producing area in a hydrocarbon producing wellbore.
 21. The method of claim 1 wherein the detrimentally permeable zone comprises an area of lost structural integrity in a set cement sheath.
 22. A method of servicing a wellbore comprising placing a composition comprising a non-aqueous carrier fluid, an oil-wetting surfactant, a water-imbibition enhancing surfactant, and a cementitious material into the wellbore, wherein the wellbore comprises hydrocarbon-producing zones and water-producing zones and wherein the composition enters the water-producing zone and forms a solid mass that obstructs the flow of water in the water-producing zone.
 23. A method of servicing wellbore comprising: placing a composition comprising a non-aqueous carrier fluid, an oil-wetting surfactant, a water-imbibition enhancing surfactant, and a cementitious material into a lost circulation zone within the wellbore; and contacting the composition in situ with a water source. 